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EDF Renewables North America Signs Power Purchase Agreement with BASF for Solar Energy

EDF Renewables North America today announced the Space City Solar Project is progressing with critical development milestones having signed the first tranche of 55 megawatts (MWac) / 73 MWdc to BASF through a Power Purchase Agreement.  The Project’s total capacity is up to 345 MWac / 455 MWdc.  Space City Solar, located in Wharton County, Texas, is expected to commence construction in Summer 2021 and begin delivery of clean electricity in Summer 2022.

Approximately 300 jobs are expected to be created during the construction phase with more than $30 million generated in new tax revenue over the operating life for Wharton County taxing entities.  In addition to providing stable payments to local landowners who chose to lease their land, the Louise Independent School District has the ability to receive $2.5 million in revenue, including $1.8 million in the first year of operation providing the district enacts a Chapter 313 Agreement by December 31, 2020.

Space City Solar is specially designed to generate clean energy while minimizing impacts to wildlife, habitat, and other environmental resources. The project will utilize high efficiency bifacial solar photovoltaic (PV) modules.

“This transaction demonstrates EDF Renewables’ continued commitment to helping corporate customers meet their wholesale power supply needs and sustainability initiatives,” said Matt McCluskey, Vice President, South Region Development for EDF Renewables. “Space City Solar will provide an economic boost to the local economy through construction jobs, local spend and an expanded tax base.”

With 35 years of experience and 16 gigawatts of renewable projects developed throughout North America, EDF Renewables provides a fully integrated bundle of energy solutions from grid-scale wind, solar, and solar plus storage projects to electric vehicle charging and energy storage management.

For more information:

ERCOT Report Shows Increasing Reserves in Coming Years

Accelerated utility-scale solar growth boosts reserve margins.

New generation resources, including a significant amount of utility-scale solar, continue to be added to the ERCOT region at a rapid pace, resulting in higher planning reserve margins over the next several years.

ERCOT today released its December Capacity, Demand and Reserves (CDR) Report, which includes planning reserve margins for the next five years. The planning reserve margin for summer 2021 is forecasted to be 15.5%, based on resource updates provided to ERCOT from generation developers and an updated peak demand forecast. This is down 1.8% from what was reported in the May CDR due to solar and wind project delays and cancellations. Between 2022 and 2025, the planning reserve margin is expected to reach 25-27%.


“In 2018 and 2019, ERCOT experienced historically-low planning reserve margins due to plant retirements,” said ERCOT President and CEO Bill Magness. “These business cycles of retirements and new investments are expected in the ERCOT market,and it is ERCOT’s job to maintain reliable electric service through the various changing conditions.” Any changes to generation resources will be accounted for in future CDR reports.

The ERCOT region continues to see growth in customer demand, and will be incorporating demand served by Lubbock Power and Light beginning in June 2021. The forecasted peak demand for summer 2021 is 77,244 MW, and was calculated using revised economic data released by Moody’s Analytics in August. ERCOT’s current system-wide peak demand record is 74,820 MW, set on Aug. 12, 2019, between 4 and 5 p.m.

ERCOT has seen a significant increase in utility-scale solar resources, and based on the grid operator’s current interconnection queue for new generation projects, this trend is expected to continue over the next several years.

The grid operator is also seeing continued and accelerated growth in rooftop solar projects. In response, ERCOT included its first, separate rooftop solar PV forecast in the CDR. The forecast was created to show the incremental capacity growth beyond the historical growth trend reflected in the load forecast.

Based on preliminary data from generation owners, planned resources expected to be available by summer 2021 have a summer-rated capacity of 5,620 MW. This includes 816 MW of gas-fired resources, 1,765 MW of wind resources and 3,039 MW of utility-scale solar resources. An additional 9,273 MW of summer-rated solar capacity is expected to be added by June 2022.

Resources totaling 1,917 MW of installed capacity have been approved by ERCOT for commercial operations since the May CDR, and a total of 12,525 MW of installed capacity became eligible for inclusion in the CDR.

While there are only a small number of battery facilities on the ERCOT system at this time, there are a significant number of battery projects in the interconnection queue. Through the Battery Energy Storage Task Force, ERCOT has worked with stakeholders to develop new market rules for integrating these resources into the ERCOT system. The next step will be to study operational data for existing batteries in order to better understand their contributions during peak hours so their capacity can be appropriately accounted for in future CDR reports.

ERCOT’s next Seasonal Assessment of Resource Adequacy will be released in March 2021, along with a preliminary summer weather assessment that considers drought conditions in Texas.As ERCOT prepares the summer assessment, it is mindful of the accelerating pace of drought in Texas, which could significantly affect summer weather and demand for electricity. The mid-year CDR report will be released in May 2021.

Background on the CDR report

The CDR report includes a look forward at all currently operational and planned resource capacity as reported to ERCOT by resource developers and owners. It provides annual projections of ERCOT’s planning reserve margins for the summer and winter seasons. The planning reserve margin is the difference between the total generation available in the ERCOT system and the forecasted firm peak demand, with the difference expressed as a percentage of the forecasted firm peak demand.


ERCOT, the Electric Reliability Council of Texas, manages the flow of electric power to more than 26 million Texas customers, representing about 90 percent of the state’s electric load. As the Independent System Operator for the region, ERCOT schedules power on an electric grid that connects more than 46,500 miles of transmission lines and 680+ generation units. ERCOT also performs financial settlement for the competitive wholesale bulk-power market and administers retail switching for more than 8 million premises in competitive choice areas. ERCOT is a membership-based 501(c)(4) nonprofit corporation, governed by a board of directors and subject to oversight by the Public Utility Commission of Texas and the Texas Legislature.

Source: ERCOT
Media Contact: Leslie Sopko, (512) 779-8345,

Low Natural Gas Prices, Not Wind Energy, Primarily Responsible for Coal’s Troubles

A repost from “Into the Wind”, blog of the American Wind Energy Association (AWEA)
by Michael Goggin

As we’ve observed previously, a common tactic when an energy source is facing market headwinds is to blame wind energy for its problems.

Just as some nuclear power plant owners previously tried to blame wind energy for their market struggles, some in the coal industry are now attempting to say wind is responsible for their challenges. Just as the previous attacks were debunked and dismissed as a “distraction,” the latest attacks on wind distract from the main market-driven challenges facing those industries.

The reality is that wind has a minimal impact on the economics of other power plants, particularly relative to low natural gas prices and stagnant electricity demand. This is because wind energy rarely sets the market price paid to all generators. Moreover, any impacts wind projects have on competing energy sources are due to market-based outcomes (i.e. wind energy’s lower costs) that occur with or without the renewable Production Tax Credit. Other sources of energy with a low fuel cost, like coal, nuclear, and hydropower, have the same impact on market prices.

The market-driven impact of wind on electricity prices is beneficial for consumers. In fact, utilities, large corporations, and others are buying wind energy precisely because it allows them to diversify their energy portfolio with a low-cost, stably priced source of energy.

Some of the clearest evidence that wind is not the main factor driving other energy sources’ market woes can be seen just by looking at where coal and nuclear power plants are retiring. Most retiring nuclear plants are in areas that have little to no wind generation, like Florida, Vermont, Wisconsin, Massachusetts, and New Jersey.

Similarly, the following maps show that the vast majority of coal power plant retirements (top map) have occurred in the eastern US, where there is relatively little wind generation (bottom map). At the same time, the wind-heavy interior region of the U.S. has seen few coal retirements, even though coal provides a larger share of the electricity mix in that area.

Rather, the primary factor driving coal power plant retirements appears to be that new shale gas production in the Marcellus region and other parts of the Eastern U.S. has undercut coal power plants operating on relatively high cost Appalachian coal.

Fossil, not wind, sets electricity market prices

Wind energy almost never sets the price received by other power plants in the electricity market, while fossil fuel power plants almost always do.

The following chart, which students of economics will recognize as the typical shape of the supply curve in any market, explains why. Power plants are listed in order of increasing operating cost, and grid operators move up the supply curve to meet electricity demand at any point in time, ensuring the lowest-cost resources available are used. Because they have no fuel cost, wind plants and other renewable resources are on the far left side of the curve, followed by nuclear, then coal, then gas, and finally oil-fired power plants. As indicated by the vertical lines, electricity demand almost always falls in the range where coal or gas power plants are the last ones needed to meet demand, and therefore the cost of operating those plants sets the market clearing price. In contrast, the wind plants on the far left side of the curve almost never set the electricity market price.

Data from grid operators confirm this is true. In the MISO (MidContinent Independent System Operator)  grid operating area, natural gas power plants set electricity prices 76 percent of the time, coal power plants 23 percent, and wind plants only 1 percent of the time (page A-6).

Data for the PJM grid operating area (page 133) show that lower natural gas prices have accounted for 68 percent of the decline in power prices since 2008, low coal prices 28 percent, and dropping oil prices 3 percent of the decline. In contrast, wind setting the electricity market price only accounts for 0.2 percent, or 1/500th, of the electricity price decline over that time.

Because fossil fuel resources set the market clearing price, low natural gas prices and subsidies for fossil fuels are directly factored into electricity market prices. In contrast, tax credits for wind energy are not incorporated into electricity market prices because wind plants almost never set the market clearing price. Therefore, a wind plant has the same impact on electricity market prices regardless of whether or not it receives the Production Tax Credit. This impact is essentially zero, as wind almost never sets the clearing price paid to all generators.

Negative prices are rare, and typically not caused by wind

Occasionally transmission constraints force a wind plant to reduce its output, as there is not enough transmission capacity for the full output to reach customers. When this occurs power prices can go low or negative on the isolated section of the power grid between the wind plant and the transmission constraint.

However, because most wind capacity is located in remote areas, there are typically no other power plants on this section of the grid, so there is little to no impact on other power plants. Fortunately, long-needed upgrades to the transmission system have greatly reduced these localized occurrences of negative prices, and further upgrades will minimize them even further (the chart on page 41 shows the downward trend of wind curtailment, which is a close proxy for trends in localized occurrences of negative prices).

Regarding recent complaints from the coal industry in North Dakota, data from the MISO grid operator confirm that wind almost never sets the electricity market price in North Dakota, with only 0.27% of prices in the range that would be set by a wind plant. In almost all hours, the electricity market prices received by North Dakota’s coal power plants are set across the 15-state MISO market footprint. With 175,000 megawatts (MW) of generation competing to determine market prices and fossil power plants almost always setting the market clearing price, North Dakota’s 2,746 MW of wind capacity, or even the total MISO wind fleet, have little impact on electricity market prices in North Dakota.

The trend in North Dakota electricity generation, shown below, confirms that in-state wind generation has a small impact on in-state coal generation in this broader market. North Dakota coal generation has remained steady while wind generation has increased to meet demand for exports and growing in-state electricity consumption, indicated by the black line.

It should also be noted that other energy sources are a leading cause of negative prices on larger sections of the grid. Data from the PJM grid operator show that wind generation is not the largest driver of negative prices at nuclear power plants in Illinois. More recent data from the Quad Cities nuclear plant in Illinois continue to show that most negative price events happened during time periods of low wind output, while most periods of high wind output do not correspond to negative price events.

From mid-2015 through mid-2016, PJM wind generation averaged only 1,845 MW during negative price events, compared to a maximum wind output of 5,021 MW and an average output of 1,681 MW across all hours. The primary factor causing negative prices at those nuclear plants still appears to be the inability of nuclear plants to reduce their output during periods of low electricity demand.

Low natural gas prices have also caused a new phenomenon that is leading coal power plants to cause negative prices. At least some coal plants have decided to continue operating at a loss as power prices go low or even negative to avoid paying contract penalties for not taking enough coal under long-term supply and delivery contracts with mines and railroads. For many coal power plants that no longer have space to add to their record coal piles, these contracts have created an out-of-market incentive to continue operating and drive power prices negative simply to burn coal to avoid contract penalties.

Data that was inadvertently publicly disclosed as part of the Peabody Coal bankruptcy further confirms that these inflexible long-term coal contracts are common; for a specific power plant in New Mexico, “The 19-year coal supply contract, originally signed in late 2005, calls for delivery of 3.7 million tons to 4.3 million tons of coal annually between 2010 and 2024, with smaller amounts provided in preceding years. The contract includes a provision that allows Peabody to collect a ‘shortfall’ payment of $7.35 per ton if the plant owners do not take the minimum contracted tonnage.”

The owner of a typical coal power plant would subtract around $8/MWh from its electricity market offers to account for the cost of that contract penalty. In addition, the large and ongoing subsidies for fossil fuels and nuclear generation also have a significant impact on electricity market prices, as discussed in the final section below.

Wind’s impact on prices is market-driven and beneficial for consumers

Wind does benefit consumers by reducing the cost of producing electricity and allowing electricity demand to be met by more efficient power plants. This market-driven impact of wind on electricity prices is beneficial for consumers, and occurs for any source of energy with a low fuel cost, such as nuclear, coal, or hydropower. In fact, utilities, corporations, and others are buying wind energy precisely because it allows them to diversify their energy portfolio with a low-cost, stably priced source of energy.

While at times wind has significantly reduced electricity prices through this market-driven phenomenon, that impact is quite small at current gas prices. Returning to a supply curve chart similar to the one introduced above, the supply curve for a power system is shown below under 2008 and 2015 fuel prices. While in 2008 natural gas power plants were significantly more expensive than coal power plants, at today’s low gas prices many natural gas power plants can operate at a cost that is comparable to the operating cost for most coal power plants. As a result, today’s supply curve is much flatter.

The slope of the supply curve determines the impact of wind on the market price. The impact of wind is to push the supply curve to the right as wind output is added to the left side of the supply curve. In 2008, adding wind energy did have a significant impact on electricity market prices by allowing electricity demand to be met using cheaper coal plants rather than more expensive natural gas power plants. For example, moving left on the supply curve from 70 GW to 65 GW of demand from conventional power plants because of the availability of 5 GW of wind energy would have reduced power prices by $35/MWh in 2008, but at today’s low gas prices that 5 GW of wind only reduces market prices by around $0.70/MWh.

Stepping back, one can also see that fossil fuel prices have a much larger impact on electricity market prices. 70 GW of demand in 2008 would have corresponded to a market price of $64/MWh, but under 2015 fossil fuel prices the electricity price is only $27/MWh, based solely on the price of natural gas. In this example, low natural gas prices have a 50 times larger impact on the electricity market price than the full impact of wind. 5 GW of wind output is quite high, roughly comparable to the average wind output in one of the U.S. electricity markets with the most wind, like MISO, Texas, or the Southwest Power Pool.

Wind accounts for less than three percent of federal energy incentives

Subsidies for fossil energy have a far larger impact on electricity prices than incentives for wind energy. Fossil fuels account for 65 percent of total federal energy subsidies, versus less than 3 percent for wind energy. Moreover, because fossil resources almost always set electricity market clearing prices, subsidies for fossil fuel production and use are directly factored into electricity market prices, unlike wind incentives.

The Home Depot Taps Texas Wind Farm for Renewable Energy

(Atlanta, Georgia)  The Home Depot® today announced its first major investment in a wind-powered renewable energy project.

The energy purchased from the wind farm is enough to power 100 Home Depot stores for a year while also providing $150,000 in local community benefits.The Los Mirasoles Wind Farm, owned and operated by EDP Renewables North America, is located in Hidalgo and Starr Counties, northeast of McAllen, Texas. Through a 20-year power purchase agreement (PPA), The Home Depot’s annual purchase of 50 megawatts (MW) is a fifth of the wind farm’s 250 MW capacity. The farm utilizes Vestas V110 2.0 MW wind turbines and produces enough power to provide more than 70,000 average U.S. homes with clean electricity each year.

The Home Depot partnered with EDP Renewables for the Texas development in 2016. EDP Renewables operates globally with 41 wind farms across North America.  As a part of its renewable energy initiative, The Home Depot’s goal is to procure 135 megawatts of various renewable energy sources, including solar and wind, by the end of 2020.

In addition to the wind farm, the company also procures energy from solar farms in Delaware and Massachusetts with a combined annual output of 14.5 million kilowatt hours (kWh). More than 150 stores and distribution centers utilize on-site fuel cells that produce roughly 85 percent of the electricity each store needs to operate.

For more on The Home Depot’s wind energy project, visit:

The Home Depot is the world’s largest home improvement specialty retailer, with 2,278 retail stores in all 50 states, the District of Columbia, Puerto Rico, U.S. Virgin Islands, Guam, 10 Canadian provinces and Mexico. In fiscal 2015, The Home Depot had sales of $88.5 billion and earnings of $7.0 billion. The Company employs more than 385,000 associates. The Home Depot’s stock is traded on the New York Stock Exchange (NYSE: HD) and is included in the Dow Jones industrial average and Standard & Poor’s 500 index.

SOURCE: The Home Depot


Negative Prices Still Rare, Mostly Caused by Other Energy Sources

Concerned about negative pricing in electricity markets?  This insightful commentary from AWEA’s Into The Wind Blog provides insight into negative pricing, its cause, and its impacts on ratepayers in ERCOT and other markets.

Original content located here: 
Celeste Wanner and Walter Reid contributed to this analysis.

Some recent press articles have again fallen into confusion over wind’s impact on electricity markets. Recent occurrences of negative prices during a few hours in some markets are actually a different phenomenon from the localized negative price events we discussed two years ago. However, two similarities to those prior events are that the new events are also largely caused by energy sources other than wind, and that both types of occurrences have a minimal impact on markets.

As background, renewable resources do tend to reduce electricity prices by displacing more expensive sources of energy, benefiting consumers. The cost and emissions savings of using wind energy to displace fossil fuel generation are precisely why wind energy has become electric utilities’ number one choice for new generating capacity. As we explained previously, wind’s impact on electricity prices is an entirely market-based outcome that also occurs for other low-fuel cost sources of energy, such as nuclear, coal, and hydropower.

Negative prices are rare, have minimal impact on average market prices

Much of the focus of recent press articles has been on the main electricity market in Texas, known as the Electric Reliability Council of Texas, or ERCOT. A close examination of wholesale electricity price data shows that negative prices accounted for only 0.64% of ERCOT-wide average market prices in 2015. These events have an even smaller impact on demand-weighted average market prices because they tend to occur during hours of lower electricity demand, and because prices go negative by only a dollar or two in almost all cases. As a result, in 2015 negative prices reduced demand-weighted average ERCOT power prices from $26.38/megawatt hour (MWh) to $26.26/MWh, a decrease of only $0.12/MWh, or less than one half of one percent.

In contrast, volatility in the price of natural gas has a profound impact on ERCOT market prices. In 2014, prices for the delivery of natural gas to power plants in Texas averaged $4.62/MCF (thousand cubic feet), yet that fell to an average of $2.88/MCF in 2015. Because natural gas power plants set the electricity market price in nearly all hours in ERCOT, average electricity prices fell from $36.41/MWh in 2014 to $26.26/MWh in 2015, a decline of 28%. This impact is nearly 100 times larger than the impact of all negative price events in 2015. As numerous sources previously explained, occurrences of negative prices have a minimal impact on generators compared to the effect of fuel price fluctuations.

Other energy sources are a leading cause of negative prices

Low natural gas prices also appear to have indirectly caused many of the negative price occurrences in ERCOT in 2015. Low natural gas prices caused many gas power plants to become cheaper to run than coal power plants in 2015, causing coal’s share of the total ERCOT generation mix to plummet from 36 percent in 2014 to 28 percent in 2015, while gas’s spiked from 41 percent to 48 percent.

However, many coal power plants have inflexible contracts with coal mines for the purchase of coal and with railroads for the delivery of that coal. As a result, while Texas coal consumption fell by 15 million tons in 2015, Texas coal deliveries only fell by 10 million tons. The extra 5 million tons were added to coal piles at power plants across Texas, leading to a 37 percent increase in coal stockpiles at Texas power plants over the course of 2015. For reference, the 19.5 million tons of coal stockpiled at Texas power plants as of the start of 2016 would fill a coal train stretching from coast to coast across the United States. The 197 million tons stockpiled at coal power plants nationwide could fill a coal train stretching nearly around the world.

Many coal power plants have limited space to stockpile coal. However, as mentioned above, coal purchase and delivery contracts often have minimum delivery requirements, which are used by the mine and railroad to guarantee revenue so they can finance capital upgrades necessary to deliver the coal. As a result of these contract provisions, the power plants must continue to take deliveries of coal even if they don’t need it, or else the power plant owner would face contract penalties or a lawsuit for breach of contract from the mine or railroad.

As a result, it appears that many power plants have decided to continue operating at a loss simply so that they can continue to burn coal to avoid those large contract penalties. In some cases it appears that these coal power plants continue producing electricity as power prices fall well below the cost of operating the plant, even as power prices go negative. The inflexibility of the coal contract provisions thus acts as an out-of-market incentive to continue operating coal power plants despite power prices going negative and sending a signal that generation should be reduced. Different policies have led to a similar outcome in China, with coal generation inefficiently displacing wind generation in some hours.

Indications of out-of-market coal generation can be seen in market data provided by ERCOT. As an example, the following chart from April 8, 2016, shows electricity demand in green and online generating capacity in red. This chart shows that many power plants are available to come online quickly (see the steep increase in the red line at around 6 AM) and increase their output in the morning and as demand increases over the course of the day. Despite the availability of those quick-starting resources, many power plants continued to operate unnecessarily through the night, even as electricity demand fell more than 10,000 MW below the level of online capacity.


With around 5,000 MW of nuclear generation and around 7,000 MW of wind generation running at essentially 100 percent of their available output that night, one can calculate that around 25,000 MW of fossil generating capacity remained online to meet an incremental need for 15,000 MW or less of generation. This indicates these fossil plants were operating at around 60 percent of their nameplate capacity on average, with many fossil power plants likely approaching the minimum level of generation they can provide while remaining online. Even though power prices fell below $7/MWh early that morning, these power plants remained online and continued generating.

Some of this behavior was likely motivated in part by the inability of coal power plants to rapidly change their output, and the fact that it is often costly and takes days to turn coal power plants on and off. For example, in some cases power plants remain online based on the expectation that power prices will go high enough to earn a profit later that day or the next day. However, the fact that power prices averaged less than $15/MWh for all of April 8, and the fact that April 8 was a Friday leading into a weekend period of low demand and low power prices, provides strong evidence that at least some coal power plants are operating at a loss to avoid coal contract penalties.

Some of the most definitive proof that the recent negative prices in ERCOT were not primarily caused by wind is that the market prices are not consistent with the prices typically offered by wind generators. In 2015, 50 of the 56 instances of negative prices were between -$1/MWh and $0/MWh, while the other 5 were between $-1 and $-2.21/MWh. In contrast, wind generators receiving the renewable Production Tax Credit (PTC) tend to offer their generation at prices in the $-20/MWh to -$35/MWh range. Texas has less than 1,000 MW of wind capacity that received a Section 1603 cash grant in lieu of the PTC, only around 1,000 to 2,000 MW of projects built prior to 2006 that are reaching the end of the 10-year PTC, and an unknown but likely small number of projects that received an Investment Tax Credit in lieu of the PTC.

As a bit more background, recent events of ERCOT-wide negative prices are different from previous occurrences of negative prices in Texas. As mentioned in our previous report, earlier this decade wind plants in West Texas were harmed by a lack of transmission capacity that led to negative prices and wind curtailment in the West region. While recent events have seen mildly negative prices across all regions of ERCOT, earlier events typically included negative prices in the -$20 to -$35/MWh range and were confined to the West region. That occurred because transmission constraints prevented wind energy from reaching consumers in large demand centers in East Texas, causing power prices to drop in West Texas while they remained high in the rest of the ERCOT. Because almost no conventional generators are located in the West region, those earlier occurrences almost exclusively affected wind generators and had little to no impact on other generators. Fortunately, building transmission largely eliminated those localized instances of negative prices and greatly reduced wind curtailment in ERCOT, and other parts of the country are seeing similar success in eliminating localized negative prices by building transmission.

Not just coal

In addition to coal, other types of generation also contribute to negative prices. In the U.S., nuclear plants almost never change their output in response to changes in demand or power prices, and hydroelectric plants sometimes continue operating despite negative power prices. For example, April is typically a period of low electricity demand and negative prices in many markets, yet April was one of only two months in 2015 when there were no ERCOT-wide negative prices; the likely cause is that one of the state’s large nuclear units was down for a refueling outage for the entire month. Natural gas power plants often sign contracts with gas pipelines that include “take or pay” provisions with inflexibility similar to that of coal contracts, with the gas power plant owner facing penalties if they do not use gas they have purchased. While coal contracts typically cover periods of several years versus several days for natural gas contracts, these inflexible fuel contracts can still cause negative prices if electricity demand falls unexpectedly but generators must still run to avoid contract penalties.

Fortunately, it is likely that over the long-term, coal supply contracts will be re-negotiated and the market will catch up to the current reality of low electricity prices caused by low natural gas prices. This should eliminate the negative electricity prices that appear to be driven by the market upheaval caused by low natural gas prices.

Transmission can also play a role in alleviating these negative prices, just as it was the solution to the earlier, more localized occurrences of negative prices. In the case of Texas, there are pending proposals to increase power transfer capacity across the asynchronous ties between ERCOT and neighboring regions. This would provide numerous benefits to generators and consumers in both ERCOT and the neighboring regions. For example, when power prices are low in ERCOT they are often high elsewhere, so consumers in those other regions can buy cheaper electricity from ERCOT generators to the benefit of both regions, and the opposite occurs during the hours when power prices are high in ERCOT and low elsewhere. Much like the interstate highway system enables trade that provides billions of dollars in benefits, a stronger electric grid also saves consumers billions.

Invenergy to Provide Clean Power to 3M Company

Renewable Energy Producer Partners with 3M to Reduce Emissions Through Wind Power.  Agreement Brings Invenergy’s Corporate Customer Renewable Energy Portfolio to 570 MW

Chicago, Illinois – Invenergy today announced that it has signed a 120 MW wind power purchase agreement (PPA) with 3M to provide the global science-based company with renewable energy to help support its operations across North America.

“3M is a global company with a commitment to sustainability and we’re very proud to help them strengthen that commitment with this agreement,” said Invenergy’s Vice President of Sales and Marketing Craig Gordon. “Corporate off-site renewable energy procurement is one of the most exciting changes we’ve seen recently in our industry as the sector nearly tripled from 2014 to 2015 with more than 3,400 MW announced. We expect 2016 to be another strong year for direct corporate procurement.”

The agreement with 3M includes the sale of wind energy from the Gunsight Wind Energy Center located in Texas. Energy from the 120 MW project will be delivered into the Electric Reliability Council of Texas (ERCOT) regional electricity grid. With the addition of Gunsight, Invenergy will operate more than 1,700 MW of power plants in the state.

“This agreement is an important and significant step toward accomplishing our company goal of increasing renewable energy to 25 percent of our total electricity use by 2025,” said Jean Bennington Sweeney, vice president, 3M Environment, Health, Safety and Sustainability. “Perhaps even more importantly, this is an exciting step in helping to transform the way the world uses energy. Innovation and partnerships like this one with Invenergy are critical to improving our business, our planet and people’s lives across the globe.”

In January, Invenergy announced a 225 MW wind power purchase agreement with Google to provide the multinational technology giant with renewable energy to help support all of its data centers worldwide. Google first announced this deal in November at the COP21 conference in Paris. And in late 2015, Invenergy also announced two separate wind power purchase agreements with Equinix, Inc. and another Fortune 500 corporation to provide the companies with renewable energy to support their ambitious corporate sustainability goals. Each of those agreements, along with the PPA with 3M, brings Invenergy’s total corporate customer renewable energy portfolio to 570 MW.

As a signatory to the American Business Act on Climate Pledge, Invenergy is dedicated not only to meeting its own sustainability goals, but to helping its corporate customers achieve their goals. Invenergy is also a founding member of Rocky Mountain Institute’s Business Renewables Center, which is a collaborative platform aimed at accelerating corporate renewable energy procurement.

About Invenergy
Invenergy is delivering innovation in energy. Invenergy and its affiliated companies develop, own, and operate large-scale renewable and other clean energy generation and storage facilities in the Americas, and Europe. Invenergy’s home office is located in Chicago and it has regional development offices in the United States, Canada, Mexico, Japan, and Europe.

Invenergy and its affiliated companies have developed more than 10,300 MW of projects that are in operation, in construction, or under contract, including wind, solar, and natural gas-fueled power generation projects and energy storage facilities. For more information, please visit

US Army Signs PPA for Texas Hybrid Wind/Solar Energy Project

Charlottesville, Virginia – Defense Logistics Agency (DLA) Energy, in coordination with the U.S. Army Office of Energy Initiatives (OEI) and Fort Hood, has signed a Renewable Energy Supply Agreement (RESA) with Apex Clean Energy Holdings, LLC, for 65.8 MW of electricity from a combination of large-scale renewable energy solar and wind facilities to serve Fort Hood in Texas. The Army is expected to pay about $168 million less than what it would pay for power from the traditional electricity grid over the course of the 28-year agreement.

Apex’s groundbreaking hybrid energy project—the Army’s largest single renewable energy project to date—is sized to optimize the solar energy produced by the Phantom Solar facility on-site at Fort Hood and the wind energy produced at the Cotton Plains Wind energy facility in Floyd County, Texas. Apex is collaborating with two Service-Disabled Veteran-Owned Small Businesses in the development and construction of the project, Tennessee Valley Infrastructure Group (TVIG) and American Helios. TVIG will serve as the Balance of Plant contractor on the wind energy component project, and American Helios Constructors will support construction of the solar component of the project.

“The project at Fort Hood, the Army’s first hybrid and largest single renewable energy project to date, is an excellent example of the extraordinary results we can achieve through collaboration,” said Katherine Hammack, assistant secretary of the Army for installations, energy, and environment. “The Army will continue to partner with private-sector entities such as Apex Clean Energy, Inc., to expand renewable energy initiatives on our installations. By working together, we can ensure a sustainable world for future generations.”

“We are proud to be working with several Service-Disabled Veteran-Owned Small Businesses to support the Department of Defense’s goals to preserve energy surety and harness more clean, domestic energy to power military facilities,” said Mark Goodwin, Apex Clean Energy president. “As a veteran myself, I am honored to be partnering with the Army on a renewable energy project that will ensure a consistent, affordable, and secure energy resource for Fort Hood for years to come.”

Apex’s hybrid project will feature 50.4 MW of wind energy from the Cotton Plains Wind energy facility in Floyd County, Texas, and 15.4 MWac solar on-site at Fort Hood. The project will begin providing energy to Fort Hood in 2017.

About Apex
Apex Clean Energy builds, owns, and operates utility-scale wind and solar power facilities. Last year, Apex completed 1,044 megawatts of new wind capacity, enough to power over half a million homes. With the nation’s largest wind energy project pipeline and billions of dollars worth of operating assets under management, Apex is a leader in the transition to a clean energy future. For more information, visit